The present invention relates, in general, to the removal of particulates and other contaminants from flue gas produced by the burning of a fossil fuel and, in particular, to a new and useful method and system which simultaneously removes sulfur trioxide (SO.sub.3) from the flue gas by injecting dry sorbent downstream of a particulate collection device, capturing reacted and unreacted dry sorbent in a wet scrubber, and removing sulfur dioxide (SO.sub.2) in the wet scrubber.
In the pollution control field, several approaches are used to remove sulfur oxides and other contaminants from a flue gas produced by the burning of a fossil fuel in order to comply with Federal and State emissions requirements. One approach involves locating and utilizing fossil fuels lower in sulfur content and/or other contaminants. A second approach involves removing or reducing the sulfur content and/or other contaminants in the fuel, prior to combustion, via mechanical and/or chemical processes. A major disadvantage to the second approach is the limited cost effectiveness of the mechanical and/or chemical processing required to achieve the mandated reduction levels of sulfur oxides and/or other contaminants.
By and large, the most widely used approaches to removing sulfur oxides and/or other contaminants from flue gas involves post-combustion clean-up of the flue gas. Several methods have been developed to remove the SO.sub.2 species from flue gases.
A first method for removing SO.sub.2 from flue gas involves either mixing dry alkali material with the fuel prior to combustion, or injection of pulverized alkali material directly into the hot combustion gases to remove sulfur oxides and other contaminants via absorption or absorption followed by oxidation. Major disadvantages of this first method include: fouling of heat transfer surfaces (which then requires more frequent soot blowing of these heat transfer surfaces), low to moderate removal efficiencies, poor reagent utilization, and increased particulate loadings in the combustion gases which may require additional conditioning (i.e. humidification or sulfur trioxide injection) of the gas if an electrostatic precipitator is used for downstream particulate collection.
A second method for removing SO.sub.2 from flue gas, collectively referred to as wet chemical absorption processes and also known as wet scrubbing, involves "washing" the hot flue gases with an aqueous alkaline solution or slurry in an upflow, gas-liquid contact device to remove sulfur oxides and other contaminants. Major disadvantages associated with these wet scrubbing processes include: the loss of liquid both to the atmosphere (i.e., due to saturation of the flue gas and mist carry-over) and to the sludge produced in the process, and the economics associated with the construction materials for the absorber module itself and all related auxiliary downstream equipment (i.e., primary/secondary dewatering and waste water treatment subsystems).
A third method, collectively referred to as spray drying chemical absorption processes and also known as dry scrubbing, involves spraying an aqueous alkaline solution or slurry which has been finely atomized via mechanical, dual-fluid or rotary cup-type atomizers, into the hot flue gases to remove sulfur oxides and other contaminants. Major disadvantages associated with these dry scrubbing processes include: moderate to high gas-side pressure drop across the spray dryer gas inlet distribution device, and limitations on the spray down temperature (i.e., the approach to flue gas saturation temperature) required to maintain controlled operations.
Several methods have been developed to remove SO.sub.3 from flue gas. One method is known as dry sorbent injection, which involves injecting a sorbent (generally lime, limestone, promoted lime, sodium bicarbonate or other alkali sodium salts, or other alkali metal salts such as silica, aluminum, iron, etc.) into the flue gas at temperatures above the adiabatic saturation temperature of the flue gas. The amount of sorbent required is highly dependent upon the sorbent properties (i.e., the composition, particle size, surface area, etc.), flue gas temperature, and method of injecting.
Spray drying chemical absorption processes, such as described above in connection with SO.sub.2 removal, are also used for SO.sub.3 control.
Wet precipitators have also been used to remove SO.sub.3 from wet flue gas streams. In these systems, the SO.sub.3 forms an aerosol of H.sub.2 SO.sub.4 by reaction with water. The aerosol behaves much like a solid particle in that it is removed when an electrical charge is applied. The aerosol is then collected by impaction on wetted plates or tubes for removal from the flue gas stream.
SO.sub.3 can also be removed via condensation. One known process is the WSA-SNOX process in which SO.sub.2 is catalytically converted to SO.sub.3. The SO.sub.3 is then removed by condensation, forming a dilute sulfuric acid. Other known methods for SO.sub.3 removal include activated carbon, and packed, moving, or fluidized bed processes. Also, combined processes which utilize a hot catalytic baghouse are known to remove SO.sub.3. Moreover, S0.sub.3 can also be removed by adding a sorbent or reagent such as MgO to the fuel.
One known system for removing SO.sub.3 from flue gas produced by a combustion process is schematically illustrated in FIG. 1. A fossil fuel 2, such as coal, is burned in a boiler 4 and the resulting flue gas 6 is passed through a heat exchanger 8 to cool the gas. SO.sub.3 from the flue gas 6 is removed in a dry scrubber 10 by contacting the flue gas 6 with an atomized reagent slurry 12 in an evaporating mode. The reagent slurry 12 used in the dry scrubber 10 is provided by a reagent preparation system 14. After dry scrubbing, the partially cleaned but particle-laden flue gas 16 is channeled to a particulate collector 18, such as a baghouse or precipitator, to remove particles from the flue gas 16. After particles are removed from the flue gas 16, the cleaned flue gas 20 exits the system through a stack 22. Reaction product 24, and collected particles and other material 26 collected in the dry scrubber 10 and particulate collector 18 are then channeled to a waste disposal device 28, while any reusable reagent from the reaction product 24 is provided back into the reagent preparation system 14. Dry scrubber systems such as shown in FIG. I have high operating costs due to both the power requirements to atomize the reagent slurry and the cost of the reagent itself. In addition, reagent utilization is poor compared to other systems such as wet scrubber systems.
FIG. 2 schematically illustrates another known system for removing SO.sub.3 from flue gas produced by the combustion of a fossil fuel. In this system, a dry injection process injects a sorbent 30 at one or more of a plurality of locations in the system. A first location 32 involves injection of the sorbent 30 directly along with the fuel 2. A second location 34 involves injection of the sorbent into the boiler 4 so that it mixes with the flue gas 6 at a location downstream of the fuel 2 injection point. A third location 36 involves injection of the sorbent 30 into the flue gas 6 just upstream or prior to its entry into the heat exchanger 8, while a fourth location 38 involves injection of the sorbent 30 into the flue gas after it exits the heat exchanger 8. The sorbent 30 is provided by a sorbent receiving and preparation station 40, while the collected particles and other materials 42 are collected in a waste disposal device 44. These dry injection processes, similar to dry scrubbers, typically require high cost reagents and are known to have poor reagent utilization, resulting in increased operating costs and quantities of waste product. Additionally, the presence of unused reagent in the waste product limits its the use as a product and detrimentally affects the properties of the waste, which impacts landfill operations. Finally, since both the reaction products and unused sorbent are captured in the particulate collector 18, the unused sorbent is not readily available for use in SO.sub.2 removal.
The known systems illustrated in FIGS. 1 and 2 remove SO.sub.3 from the flue gas prior to removal of particulates from the flue gas in the particulate collector 18. In some cases, these sulfur oxide removal processes significantly affect the performance of the particulate collector 18 due to the increased particulate loading which occurs when the reaction product is provided to the particulate collector 18. If the particulate collector 18 is an electrostatic precipitator, there is also a great chance of changing the resistivity of the particles which affects the collection efficiency.
It is well-known in the pollution control field that a wet scrubber does not effectively remove SO.sub.3 from flue gas. In wet scrubber systems, the rapid quenching of the flue gas that occurs when the hot gas is contacted with water or an aqueous stream results in formation of aerosol H.sub.2 SO.sub.4. These very fine droplets of H.sub.2 SO.sub.4 tend to pass on through the wet scrubber without being removed from the flue gas. Recent tests conducted on a wet scrubber pilot plant receiving hot flue gas from a coal fired boiler plant indicated that only 25-35% of the SO.sub.3 in the flue gas at the inlet to the wet scrubber was removed for inlet SO.sub.3 concentrations of 9 to 25 ppm. Although SO.sub.3 typically comprises only a small portion of the sulfur oxides in the flue gas produced in such combustion processes, even small excess amounts of SO.sub.3 in the flue gas emitted from the stack at such a plant can result in a visible plume which may cause the plant to exceed regulatory requirements for opacity or SO.sub.3 emissions.
Other known systems for SO.sub.3 removal from flue gas require additional equipment, are very complicated in design and operation, and provide a very costly method for removing SO.sub.2 and SO.sub.3. It is thus apparent that a simple and economical method and system is still needed to remove both SO.sub.2 and SO.sub.3 from the flue gas produced by the burning of a fossil fuel that overcomes the disadvantages of these prior approaches.